1. Field of the Disclosure
This disclosure relates generally to oilfield wellbore drilling systems and more particularly to drilling fluid circulation systems that utilize a wellbore fluid circulation device to optimize drilling fluid circulation.
2. Background of the Art
Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drill pipe (tubing) that has at its bottom end a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) that carries the drill bit for drilling the wellbore. The drill pipe is made of jointed pipes. Alternatively, coiled tubing may be utilized to carry the drilling of assembly. The drilling assembly usually includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped under pressure from a source at the surface down the tubing. The drilling fluid drives the mud motor and then discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore inside and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at a work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. In riser-type drilling, a riser, which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the sea surface.
During drilling with conventional drilling fluid circulation systems, the drilling operator attempts to carefully control the fluid density at the surface so as to control pressure in the wellbore, including the bottomhole pressure. Referring to FIG. 1A, there is shown a surface pump P1 at the surface S1 for pumping a supply fluid SF1 via a drill string DS1 into a wellbore W1. The return fluid RF1 flows up an annulus A1 formed by the drill string DS1 and wall of the wellbore W1. The drilling fluid in the annulus A1 carries with it the cuttings C1 generated by the cutting action of a drill bit (not shown). The drill string DS1 is shown separately from the wellbore W1 to better illustrate the flow path of the circulating drilling fluid. Typically, the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out. Under this regime, the surface pump P1 has the burden of flowing the drilling fluid down the drill string DS1 and also upwards along the annulus A1. Accordingly, the surface pump P1 must overcome the frictional losses along both of these paths. Moreover, the surface pump P1 must maintain a flow rate in the annulus A1 that provides sufficient fluid velocity to carry entrained cuttings C1 to the surface. Thus, in this conventional arrangement, the pumping capacity of the surface pump P1 is typically selected to (i) overcome frictional losses present as the drilling fluid flows through the drill string DS1 and the annulus A1; and (ii) provide a flow velocity or flow rate that can carry or lift the cuttings C1 through the annulus A1. It will be appreciated that such pumps must have relatively large pressure and flow rate capacities. Furthermore, these relatively large pressures can damage the exposed formation F1 (or “open hole”) below the casing CA1. For instance, the fluid pressure needed to provide the desired fluid flow rate can fracture the rock or earth forming the wall of the wellbore W1 and thereby compromise the integrity of the wellbore W1 at the exposed and unprotected formation F1.
In another conventional drilling arrangement shown in FIG. 1B, there is shown a pump P2 at the surface for pumping a supply fluid SF2 via an annulus A2 into a wellbore W2. The return fluid RF2 flows up the drill string DS2 carrying with it the entrained cuttings C2. In this regime, the surface pump P2 also has the burden of flowing the drilling fluid down the drill string DS2 and also upwards along the annulus A2. Accordingly, the surface pump P2 must overcome the frictional losses along both of these paths. Further, because the cross-sectional area of the drill string DS2 is smaller than the cross sectional area of the annulus A2, the density of the return fluid RF2 and cuttings C2 flowing in the drill string DS2 is higher than the density of the return fluid RF1 and cuttings in the annulus A1 of FIG. 1A under similar drilling conditions (e.g., the same rate of penetration (ROP)). This higher fluid density requires a correspondingly higher pressure differential and flow rate in order to lift the cuttings C2 to the surface S2. Thus, in this conventional arrangement, the pumping capacity of the surface pump P2 is typically selected to (i) overcome frictional losses present as the drilling fluid flows through the annulus A and the drill string DS2; and (ii) provide a flow velocity or flow rate that can carry or lift the cuttings C2 through the annulus A2. It will be appreciated that such pumps must also have relatively large pressure and flow rate capacities.
The present disclosure addresses these and other drawbacks of conventional fluid circulation systems for supporting well construction activity.